Dynamic logging speed

ABSTRACT

Data from a string of multiple formation evaluation data sensor are evaluated. Based on the analysis, the logging speed is increased if all the sensors justify it, and is reduced if any of the sensors require a reduced logging speed.

FIELD OF THE INVENTION

This invention relates generally to methods of improved logging usingoilfield borehole tools and more particularly to dynamic adjustment ofthe logging speed based on the quality of the acquired data and theformations being evaluated.

BACKGROUND OF THE ART

Oil or gas wells are often surveyed to determine one or more geological,petrophysical, geophysical, and well production properties (“parametersof interest”) using electronic measuring instruments conveyed into theborehole by an umbilical such as a cable, a wireline, slickline, drillpipe or coiled tubing. Tools adapted to perform such surveys arecommonly referred to as formation evaluation tools. These tools useelectrical, acoustical, nuclear and/or magnetic energy to stimulate theformations and fluids within the borehole and measure the response ofthe formations and fluids. The measurements made by downhole instrumentsare transmitted back to the surface. In many instances, multiple tripsor logging runs are needed to collect the necessary data. Additionally,the logging speed is usually a predetermined fixed quantity.

In order to reduce the amount of rig time needed for wireline logging,it is common practice to run multiple sensors in a single run. FOCUS™,from Baker Atlas Inc., is a high efficiency premium open hole loggingsystems. (Note the grammatical error. Also, FOCUS should not be called a“premium” system, because it does not have our standard temperature andpressure rating). All of the downhole instruments have been redesigned,incorporating advanced downhole sensor technology, into shorter,lighter, more reliable logging instruments, capable of providingformation evaluation measurements with the same precision and accuracyas the industry's highest quality sensors, at much higher loggingspeeds. Logging speeds are up to twice the speed of conventionaltriple-combo and quad combo logging tool strings. Speeds of upto 3600ft/hr (1080 m/min) are possible. The logging system may include fourstandard major open hole measurements (resistivity, density, neutron,acoustic) plus auxiliary services.

The resolution and accuracy of logging measurements is determined by thetype of measurement and the type of formation being logged. Themeasurement may be tailored to the type of formation. For example, U.S.Pat. No. 5,309,098 to Coates et al. teaches a method and apparatus inwhich a variable time-window echo-recording system is used to obtainsignificant improvements in signal quality and logging speed. An initialtest is performed to provide an assessment of the relaxation qualitiesof the sample. If the test reveals that the sample is a slow-relaxationrock, then the full time is allocated to measuring echoes. However, ifthe test reveals that the sample is a fast decay rock, then the echoacquisition time window is reduced. This provides increased efficiencysince the system is able to maximize the number of measurements made byoptimizing the individual sampling intervals to the particular geologicstructure being tested.

Generally, prior art methods have conducted logging at a uniform loggingspeed. A fixed logging speed is used for the entire logging interval.This flies in the face of logic since reservoir intervals form only asmall portion of the entire geologic section and it is only in reservoirintervals is it necessary to get precise and accurate measurements withhigh resolution: in the non-reservoir intervals, high precision andaccuracy are not usually necessary.

It would be desirable to have a method and apparatus of logging aborehole in which the inefficiencies of the prior art are overcome. Suchan invention should preferably be able to accommodate a variety oflogging tools. The present invention satisfies this need.

SUMMARY OF THE INVENTION

The present invention is a method of, and an apparatus for conductinglogging operations of a borehole in an earth. A string of formationevaluation (FE) sensors are conveyed on a conveyance device such as awireline or a slickline into the borehole. The conveyance device isoperated at a logging speed while making measurements with said FEsensors. The measurements made by said FE sensors are analyzed, andbased on the analysis, a signal for alteration of the logging speed maybe provided. The FE sensors are selected from the group consisting of(i) a resistivity sensor, (ii) a natural gamma ray sensor, (iii) aporosity sensor, (iv) a density sensor, (v) a nuclear magnetic resonancesensor, and, (vi) an acoustic sensor. The signal may be for either anincrease or a decrease in logging speed. Based on the signal, thelogging speed may be increased or decreased.

The logging speed is increased if all the FE sensors provide a validindication that the logging speed may be increased while maintainingacceptable data quality. The logging speed is decreased if one or moreof the FE sensors provide a valid indication that data quality is notacceptable at the current logging speed. The processing of themeasurements may be carried out by a downhole processor, a surfaceprocessor, or in part by both a downhole processor and a surfaceprocessor.

Based on the analysis, additional sensors on the string may beactivated. Correction of the measurements following an alteration of thelogging speed may be done to compensate for “yo-yoing” of the wirelineor slickline. The term “yo-yo” as used in the context of the presentinvention refers to irregular speed of the downhole logging tool evenwhen the cable is being pulled up at the surface at a uniform speed.

BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present invention, reference should bemade to the following detailed description of the preferred embodiment,taken in conjunction with the accompanying drawing and in which:

FIG. 1 (prior art) is a schematic illustration of a wireline loggingsystem including a plurality of sensors.

FIG. 2 (prior art) is an embodiment of a system using a radiallyadjustable module adapted for use in logging operations;

FIG. 3 (prior art) illustrates a sectional view of one embodiment of apositioning device made in accordance with the present invention;

FIG. 4 (prior art) is a schematic elevation view of radially adjustablemodule positioned in an open hole portion of a borehole;

FIG. 5 is a schematic illustration of steps involved in the method ofthe present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is discussed with reference to specific logginginstruments that may form part of a string of several logginginstruments for conducting wireline logging operations. It is to beunderstood that the choice of the specific instruments discussed hereinis not to be construed as a limitation and that the method of thepresent invention may also be used with other logging instruments aswell.

A typical configuration of the logging system is shown in FIG. 1. Thisis a modification of an arrangement from U.S. Pat. No. 4,953,399 toFertl et al. having the same assignee as the present invention and thecontents of which are incorporated herein by reference. Shown in FIG. 1is a suite of logging instruments 10, disposed within a borehole 11penetrating an earth formation 13, illustrated in vertical section, andcoupled to equipment at the earth's surface in accordance with themethod and apparatus for determining characteristics of clay-bearingformations of the present invention. Logging instrument suite 10 mayinclude a resistivity device 12, a natural gamma ray device 14, and twoporosity-determining devices, such as a neutron device 16 and a densitydevice 18. Collectively, these devices and others used in the boreholefor logging operations are referred to as formation evaluation sensors.Resistivity device 12 may be one of a number of different types ofinstruments known to the art for measuring the electrical resistivity offormations surrounding a borehole so long as such device has arelatively deep depth of investigation. For example, a HDIL (HighDefinition Induction Logging) device such as that described in U.S. Pat.No. 5,452,761 to Beard et al. having the same assignee as the presentinvention and the contents of which are fully incorporated herein byreference may be used. Natural gamma ray device 14 may be of a typeincluding a scintillation detector including a scintillation crystalcooperatively coupled to a photomultiplier tube such that when thecrystal is impinged by gamma rays a succession of electrical pulses isgenerated, such pulses having a magnitude proportional to the energy ofthe impinging gamma rays. Neutron device 16 may be one of several typesknown to the art for using the response characteristics of the formationto neutron radiation to determine formation porosity. Such a device isessentially responsive to the neutron moderating properties of theformation. Density device 18 may be a conventional gamma-gamma densityinstrument such as that described in U.S. Pat. No. 3,321,625 to Wahl,used to determine the bulk density of the formation. A downholeprocessor may be provided at a suitable location as part of theinstrument suite.

Instrument suite 10 is conveyed within borehole 11 by a cable 20containing electrical conductors (not illustrated) for communicatingelectrical signals between instrument suite 10 and the surfaceelectronics, indicated generally at 22, located at the earth's surface.Logging devices 12, 14, 16 and 18 within instrument suite 10 arecooperatively coupled such that electrical signals may be communicatedbetween each device 12, 14, 16 and 18 and surface electronics 22. Cable20 is attached to a drum 24 at the earth's surface in a manner familiarto the art. Instrument suite 10 is caused to traverse borehole 11 byspooling cable 20 on to or off of drum 24, also in a manner familiar tothe art.

Surface electronics 22 may include such electronic circuitry as isnecessary to operate devices 12, 14, 16 and 18 within instrument suite10 and to process the data therefrom. Some of the processing may be donedownhole. In particular, the processing needed for making decisions onspeeding up (discussed below) for slowing down the logging speed ispreferably down downhole. If such processing is done downhole, thentelemetry of instructions to speed up or slow down the logging could becarried out substantially in real time. This avoids potential delaysthat could occur if large quantities of data were to be telemetereduphole for the processing needed to make the decisions to alter thelogging speed. It should be noted that with sufficiently fastcommunication rates, it makes no difference where the decision making iscarried out. However, with present data rates available on wirelines,the decision making is preferably done downhole.

Control circuitry 26 contains such power supplies as are required foroperation of the chosen embodiments of logging devices within instrumentsuite 10 and further contains such electronic circuitry as is necessaryto process and normalize the signals from such devices 12, 14, 16 and 18in a conventional manner to yield generally continuous records, or logs,of data pertaining to the formations surrounding borehole 11. These logsmay then be electronically stored in data storage 32 prior to furtherprocessing. The processor 28 includes the ability, such as thatdescribed in U.S. Pat. No. 4,271,356 to Groeschel et al, for separatingradiation measurements from natural gamma ray device 14 into individualenergy bands centered about energy peaks of selected elemental sourcesof radiation, preferably the energy peaks of potassium, uranium andthorium. This processing of the natural gamma ray device could also bedone by the downhole processor.

Surface electronics 22 may also include such equipment as willfacilitate machine implementation of the method of the presentinvention. Processor 28 may be of various forms but preferably is anappropriate digital computer programmed to process data from loggingdevices 12, 14, 16 and 18. Memory unit 30 and data storage unit 32 areeach of a type to cooperatively interface with processor 28 and/orcontrol circuitry 26. Depth controller 34 determines the longitudinalmovement of instrument suite 20 with borehole 11 and communicates asignal representative of such movement to processor 28. The loggingspeed is altered in accordance with speedup or slowdown signals that maybe communicated from the downhole processor, or provided by the surfaceprocessor, as discussed below. This is done by altering the rotationspeed of the drum 24. Offsite communication may be provided, for exampleby a satellite link, by the telemetry unit 36.

While running different logging instruments in a single wireline run,the present invention may use a configuration disclosed in U.S. patentapplication Ser. No. ______ of Frost et al. filed under Attorney DocketNumber 584-30697 on Feb. 17, 2004. The teachings of Frost recognize thefact that different logging instruments operate best at differentstandoffs from the borehole wall.

Referring next to FIG. 2, there is shown a rig 10 on the surface that ispositioned over a subterranean formation of interest. The rig 10 can bea part of a land or offshore a well production/construction facility. Aborehole formed below the rig 10 includes a cased portion 42 and an openhole portion 11. In certain instances (e.g., during drilling,completion, work-over, etc.), a logging operation is conducted tocollect information relating to the formation and the borehole.Typically, a tool system 100 is conveyed downhole via a wireline 20 tomeasure one or more parameters of interest relating to the boreholeand/or the formation 13. The term “wireline” as used hereinafterincludes a cable, a wireline, as well as a slickline. The tool system100 can include an instrument suite comprising one or more modules 102a,b, each of which has a tool or a plurality of tools 104 a,b, adaptedto perform one or more downhole tasks. The term “module” should beunderstood to be a device such as a sonde or sub that is suited toenclose, house, or otherwise support a device that is to be deployedinto a borehole. While two proximally positioned modules 102 a,b and twoassociated tools 104 a,b, are shown, it should be understood that agreater or fewer number may be used.

In one embodiment, the tool 104 a is a formation evaluation sensoradapted to measure one or more parameters of interest relating to theformation or borehole. It should be understood that the term formationevaluation sensor encompasses measurement devices, sensors, and otherlike devices that, actively or passively, collect data about the variouscharacteristics of the formation, directional sensors for providinginformation about the tool orientation and direction of movement,formation testing sensors for providing information about thecharacteristics of the reservoir fluid and for evaluating the reservoirconditions. The formation evaluation sensors may include resistivitysensors for determining the formation resistivity, dielectric constantand the presence or absence of hydrocarbons, acoustic sensors fordetermining the acoustic porosity of the formation and the bed boundaryin formation, nuclear sensors for determining the formation density,nuclear porosity and certain rock characteristics, nuclear magneticresonance sensors for determining the porosity and other petrophysicalcharacteristics of the formation. The direction and position sensorspreferably include a combination of one or more accelerometers and oneor more gyroscopes or magnetometers. The accelerometers preferablyprovide measurements along three axes. The formation testing sensorscollect formation fluid samples and determine the properties of theformation fluid, which include physical properties and chemicalproperties. Pressure measurements of the formation provide informationabout the reservoir characteristics.

The tool system 100 can include telemetry equipment 150, a local ordownhole controller 152 and a downhole power supply 154. The telemetryequipment 150 provides two-way communication for exchanging data signalsbetween a surface controller 112 and the tool system 100 as well as fortransmitting control signals from the surface processor 112 to the toolsystem 100.

In an exemplary arrangement, and not by way of limitation, a firstmodule 102 a includes a tool 104 a configured to measure a firstparameter of interest and a second module 102 b includes a tool 104 bthat is configured to measure a second parameter of interest that iseither the same as or different from the first parameter of interest. Inorder to execute their assigned tasks, tools 104 a and 104 b may need tobe in different positions. The positions can be with reference to anobject such as a borehole, borehole wall, and/or other proximallypositioned tooling. Also, the term “position” is meant to encompass aradial position, inclination, and azimuthal orientation. Merely forconvenience, the longitudinal axis of the borehole (“borehole axis”)will be used as a reference axis to describe the relative radialpositioning of the tools 104 a,b. Other objects or points can also beused as a reference frame against which movement or position can bedescribed. Moreover, in certain instances, the tasks of the tools 104a,b can change during a borehole-related operation. Generally speaking,tool 104 a can be adapted to execute a selected task based on one ormore selected factors. These factors can include, but not limited to,depth, time, changes in formation characteristics, and the changes intasks of other tools.

Modules 102 a and 102 b may each be provided with positioning devices140 a, 140 b, respectively. The positioning device 140 is configured tomaintain a module 102 at a selected radial position relative to areference position (e.g., borehole axis). The position device 140 alsoadjusts the radial position of module 102 upon receiving a surfacecommand signal and/or automatically in a closed-loop type manner. Thisselected radial position is maintained or adjusted independently of theradial position(s) of an adjacent downhole device (e.g., measurementtools, sonde, module, sub, or other like equipment). An articulatedmember, such a flexible joint 156 which couples the module 102 to thetool system 100 provides a degree of bending or pivoting to accommodatethe radial positioning differences between adjacent modules and/or otherequipment (for example a processor sonde or other equipment). In otherembodiments, one or more of the positioning devices has fixedpositioning members.

The positioning device 140 may include a body 142 having a plurality ofpositioning members 144(a,b,c) circumferentially disposed in aspace-apart relation around the body 142. The members 144(a,b,c) areadapted to independently move between an extended position and aretracted position. The extended position can be either a fixed distanceor an adjustable distance. Suitable positioning members 144(a,b,c)include ribs, pads, pistons, cams, inflatable bladders or other devicesadapted to engage a surface such as a borehole wall or casing interior.In certain embodiments, the positioning members 144(a,b,c) can beconfigured to temporarily lock or anchor the tool in a fixed positionrelative to the borehole and/or allow the tool to move along theborehole.

Drive assemblies 146(a,b,c) are used to move the members 144(a,b,c).Exemplary embodiments of drive assemblies 146(a,b,c) include anelectro-mechanical system (e.g., an electric motor coupled to amechanical linkage), a hydraulically-driven system (e.g., apiston-cylinder arrangement fed with pressurized fluid), or othersuitable system for moving the members 144(a,b,c) between the extendedand retracted positions. The drive assemblies 146(a,b,c) and the members144(a,b,c) can be configured to provide a fixed or adjustable amount offorce against the borehole wall. For instance, in a positioning mode,actuation of the drive assemblies 146(a,b,c) can position the tool in aselected radial alignment or position. The force applied to the boreholewall, however, is not so great as to prevent the tool from being movedalong the borehole. In a locking mode, actuation of the drive assembly146(a,b,c) can produce a sufficiently high frictional force between themembers 144(a,b,c) and the borehole wall as to prevent substantialrelative movement. In certain embodiments, a biasing member (not shown)can be used to maintain the positioning members 144(a,b,c) in apre-determined reference position. In one exemplary configuration, thebiasing member (not shown) maintains the positioning member 144(a,b,c)in the extended position, which would provide centralized positioningfor the module. In this configuration, energizing the drive assemblyovercomes the biasing force of the biasing member and moves one or moreof the positioning members into a specified radial position, which wouldprovide decentralized positioning for the module. In another exemplaryconfiguration, the biasing member can maintain the positioning membersin a retracted state within the housing of the positioning device. Itwill be seen that such an arrangement will reduce the cross sectionalprofile of the module and, for example, lower the risk that the modulegets stuck in a restriction in the borehole.

The positioning device 140 and drive assembly 146(a,b,c) can beenergized by a downhole power supply (e.g., a battery or closed-loophydraulic fluid supply) or a surface power source that transmits anenergy stream (e.g., electricity or pressurized fluid) via a suitableconduit, such as the umbilical 120. Further, while one drive assembly(e.g., drive assembly 146 a) is shown paired with one positioning member144 (e.g., position member 144 a), other embodiments can use one driveassembly to move two or more positioning members.

Referring now to FIG. 4 there is shown an exemplary formation evaluationtool system 200 disposed in an open hole section 11. The tool system 200includes a plurality of modules or subs for measuring parameters ofinterest. An exemplary module 202 is shown coupled to an upper toolsection 204 and a lower tool section 206 by a flexible member 156. Inone exemplary embodiment, the module 202 supports an NMR tool 208. Asdiscussed in U.S. Pat. No. 6,525,535 to Reiderman et al., depending uponthe size of the borehole, the NMR tool may be operated in either acentralized manner or in an eccentric manner. In the open hole 18, theacoustic tool 208 may be set in a decentralized position (i.e., radiallyeccentric position) by actuating the positioning members 140 a and 140b. This decentralized or radially offset position is substantiallyindependent of the radial positions of the downhole device (e.g.,measurement devices and sensors) along or in the upper/lower tool stringsection 204 and 206. That is, the upper or tool string section 204 and206 can have formation evaluation sensors and measurement devices thatare in a radial position that is different from that of the module 202.In this decentralized or radially offset position, the NMR tool can beused to gather data in large diameter boreholes. In a small diameterborehole, the NMR tool may be operated in a central position of theborehole. It should be appreciated that such motion can be accomplishedby sequentially varying the distance of extension/retraction of thepositioning members.

Referring next to FIG. 5, a flow chart generally illustrating the methodof the present invention is shown. The downhole tool system is operatingat an initial logging speed 301. The initial logging speed may bedetermined based on prior knowledge of the expected geologic formationsand fluids. Measurements are made with a plurality of formationevaluation sensors. To simplify the illustration, only two such FEsensors depicted by 303 and 305 are shown. In actual practice, there maybe more than two FE sensors in the logging system. As will be discussedlater, the signals measured by the sensor 305 are analyzed by aprocessor, preferably the downhole processor, to see if the data qualityare good enough to permit a speedup 323 of logging. The processing mayalso be done by a surface processor, or by both a surface processor anda downhole processor. Similarly, the signals measured by sensor 303 areanalyzed by a processor to see if the data quality are good enough topermit a speedup 333 of logging. The specific nature of the check isdiscussed below with reference to individual sensor types. Similarly,the measurements of sensor 303 are checked to see if a speedup iswarranted 333. If all the sensors provide a speedup signal 329, aspeedup signal is provided 321. Not shown in FIG. 4 is a check to makesure that all the speedup signals are valid. Possible situations inwhich a speedup signal may not be valid are discussed below.

Checks are also made to see if the sensor 305 would require a slowerlogging speed 327 with a similar check to see if the sensor 303 wouldrequire a slower logging speed 335. The specific nature of the check forslower logging speed is discussed later. If at least one of the sensorsprovide a valid slowdown signal 337, then logging is slowed down 331. Itshould further be noted that the order of performing the slowdown andspeedup evaluation in FIG. 4 is for illustrative purposes only, and theevaluation could be performed in the opposite order. An importantfeature of the invention is summarized in the following test:

-   1. If all the sensors provide a valid speedup signal, then logging    speed is increased;-   2. If one or more of the sensors provide a valid slowdown signal,    then logging speed is decreased; and-   3. If neither (1) nor (2) occurs, the logging speed is maintained.

The decision as to whether to speed up or slow down the logging may bebased on a comparison measurements made over several time intervals.With the natural gamma ray tool, a typical sampling rate is 10 ms. Witha logging speed of 1200 ft/hr, 100 samples are obtained every second,which corresponds to a distance of four inches. If the average and/orthe variance of measurements over say 1 second is substantially the sameas the average of measurements over 2 seconds, it is an indication thatlogging speed may be increased without loss of resolution of loss ofprecision. With the HDIL tool, for example, transmitter and receivercoils are configured to operate with different depths of investigationby operating at several frequencies and/or by using data from severaltransmitter-receiver spacings. There is a high degree of redundancy inthe data. Again, by comparing averages over different time intervals, anindication can be obtained as to whether logging speed may be increased,or, conversely, whether logging speed should be decreased.

With nuclear sensors such as used for neutron porosity or gamma raydensity logs, the count rates are subject to statistical fluctuations.This is due to the fact that over short time intervals, the source emitsradiation that may fluctuate, and furthermore, the interaction of thesource radiation with nuclei in the formation is also governed bystatistical processes. In order to make a meaningful determination ofporosity and/or density, it becomes important to make sure that theactual number of accumulated counts has a minimum value for all thedetectors used in making the nuclear measurements.

Another point to note with respect to nuclear sensors is that somecompensation is applied to account for offset of the detectors from theborehole wall. For example, if ρ_(ss) and ρ_(ls) are measurements madeby short spaced (SS) and long spaced (LS) sensors, a density correctionis applied to give a corrected density according to the relation:Δρ=ρ−ρ_(LS) =f(ρ_(LS)−ρ_(SS))  (1)This is called the “spine and rib” correction. In situations where thereare washouts, is possible that the individual sensor measurements maypass the tests described above regarding the count rate and thestatistical fluctuations. Nevertheless, a corrected density measurementsmay still be invalid due to the large washout. This is an example of therequirement that the speedup or slowdown indicator (discussed above) bea valid one.

An acoustic sensor may also be part of the instrument suite. This isgenerally used at least for measurements of compressional (P-wave)velocities of earth formations. To make measurements of P-wavevelocities, the transmitter(s) and receivers that comprise the acousticsensor are operated in a monopole mode. Energy generated by thetransmitter travels through the formation as a refracted P-wave and fromtraveltime measurements at the array of receivers, the P-wave velocitycan be determined. The semblance of the received signal is an indicationof the quality of the data, and if the semblance is sufficiently high,then it is possible to increase the logging speed without detriment. Itshould be noted that if the formation shear wave (S-wave) velocity isgreater than the velocity of sound in the drilling mud, it is possibleto determine formation S-velocities using a monopole excitation.

The acoustic tool may also be operated in a dipole mode in which shearwaves (S-waves) are excited in the formation. Again, the semblance ofthe received signals may be used as an indicator for possible speedup oflogging speed. It should be noted that acoustic measurements takeseveral milliseconds to make, compared to the few microseconds neededfor nuclear and resistivity measurements. The acoustic tool may also beoperated in the so-called cross-dipole mode wherein the transmitter isactivated in a first dipole mode and then activated in a second dipolemode orthogonal to the first dipole mode. The cross-dipole mode isuseful in determining azimuthal anisotropy in the earth formation, anindication of possible fracturing. It should be clear that with respectto the acoustic tool, the speedup or slowdown indicator is based on allof the modes of acquisition that are desired.

For logging in laminated reservoirs (that have transverse isotropy inboth resistivity and acoustic properties), a multicomponent resistivitysensor may be included in the instrument suite. Service with such asensor is provided by Baker Hughes Incorporated under the mark 3DEX^(SM)and a tool suitable for the purpose is disclosed in U.S. Pat. No.6,147,496 to Strack et al. Using such a device, it is possible todetermine resistivity anisotropy in the earth formation that is a betterindication of reservoir quality than the HDIL measurements (that aresensitive only to horizontal resistivity). In anisotropic reservoirs, itmay also be desirable to operate the acoustic sensor in the dipole mode.The natural gamma ray sensors do not necessarily have the resolution tobe able to identify laminations at the scale at which resistivty and/oracoustic anisotropy may occur. Consequently, it may be desirable toinclude a high resolution resistivity sensor, such as a microlaterolog,as part of the instrument suite. Signals from such a sensor could beused to start acquisition with the 3DEX device and/or to switch theacoustic sensor to joint monopole/dipole operation.

As would be known to those versed in the art, wireline loggingoperations are typically conducted with the instrument suite beingpulled up the borehole. This is preferable to logging with theinstrument suite being lowered into the borehole since in the lattersituation, there may be sticking of the instrument suite into theborehole with the result that the logging depth as determined at thesurface location may not correspond to the actual depth of theinstruments. With the variations in logging speed that are possibleduring practice of the present invention, due to the elasticity of thewireline, there may be “yo-yoing” of the instrument suite at the bottomof the wireline. U.S. Pat. Nos. 6,154,704 and 6,256,587 to Jericevic etal., having the same assignee as the present application and thecontents of which are fully incorporated herein by reference, presentmethods for correcting the measurements for the effects of the yo-yoing.In the context of the present invention, this correction may be madeafter the logging operations are conducted on the stored data at thesurface. Alternatively, a correction may be applied downhole prior toany determination to speed up or slow down logging speed.

The present invention has been described in the context of a wirelinedevice. The method of the present invention is equally applicable onslickline conveyed device wherein a downhole processor is used forproviding a signal to speed up or slow down the speed. The slickline mayoptionally be conveyed inside a drilling tubular. The FE sensormeasurements are stored in a downhole memory for subsequent retrieval.

While the foregoing disclosure is directed to the preferred embodimentsof the invention, various modifications will be apparent to thoseskilled in the art. It is intended that all variations within the scopeof the appended claims be embraced by the foregoing disclosure.

1. A method of conducting logging operations of a borehole in an earthformation, the method comprising: (a) conveying a plurality of formationevaluation (FE) sensors on a conveyance device into said borehole; (b)using said conveyance device to move said plurality of FE sensors at alogging speed while making measurements with said FE sensors; (c)analyzing said measurements made by said FE sensors; and (d) alteringsaid logging speed based on said analysis.
 2. The method of claim 1wherein said FE sensors are selected from the group consisting of (i) aresistivity sensor, (ii) a natural gamma ray sensor, (iii) a porositysensor, (iv) a density sensor, (v) a nuclear magnetic resonance sensor,and, (vi) an acoustic sensor.
 3. The method of claim 1 wherein saidconveyance device comprises a slickline.
 4. The method of claim 1wherein said conveyance device comprises a wireline.
 5. The method ofclaim 4 further comprising positioning one of said plurality of sensorsat a different distance from a center of said borehole from another oneof said plurality of sensors.
 6. The method of claim 1 wherein saidalteration comprises an increase in said logging speed.
 7. The method ofclaim 1 wherein said alteration comprises a decrease in said loggingspeed.
 8. The method of claim 6 wherein said altering further comprises:(i) analyzing measurements made by each of said plurality of FE sensorsfor validity, and (ii) determining if measurements made by each of saidFE sensors would be of acceptable quality at an increased logging speed.9. The method of claim 7 wherein said altering further comprises: (i)analyzing measurements made by at least one of said plurality of FEsensors for validity, and (ii) determining if measurements made by saidat least one of said plurality of FE sensors is of unacceptable qualityat said logging speed.
 10. The method of claim 1 wherein (c) and (d) arecarried out using a downhole processor.
 11. The method of claim 1wherein (c) and (d) are carried out using a surface processor. 12.(canceled)
 13. The method of claim 1 wherein one of said FE sensorcomprises a microresistivity sensor, the method further comprisingproviding a signal based on a measurement made by said microresistivitysensor to activate at least one of (i) a multicomponent resistivitysensor, and, (ii) an acoustic sensor in a dipole mode.
 14. The method ofclaim 12 further comprising correcting measurements made by at least oneof said FE sensors following said alteration of said logging speed tocorrect for “yo-yoing” of said conveyance device.
 15. An apparatus forconducting logging operations of a borehole in an earth formation, theapparatus comprising: (a) a plurality of formation evaluation (FE)sensors; (b) a conveyance device to move said plurality of FE sensors ata logging speed while making measurements with said FE sensors; (c) aprocessor for analyzing said measurements made by said FE sensors; and(d) a processor which alters said logging speed based on said analysis.16. The apparatus of claim 15 wherein at least one of said processors in(c) and (d) is at a downhole location.
 17. The apparatus of claim 16wherein said at least one processor includes a memory for storing saidmeasurements.
 18. The apparatus of claim 15 wherein said FE sensors areselected from the group consisting of (i) a resistivity sensor, (ii) anatural gamma ray sensor, (iii) a porosity sensor, (iv) a densitysensor, (v) a nuclear magnetic resonance sensor, and, (vi) an acousticsensor.
 19. The apparatus of claim 15 wherein said conveyance devicecomprises a slickline.
 20. The apparatus of claim 15 wherein saidconveyance device comprises a wireline.
 21. The apparatus of claim 20further comprising a device for positioning one of said plurality ofsensors at a different distance from a center of said borehole fromanother one of said plurality of sensors.
 22. The apparatus of claim 15wherein said alteration comprises an increase in said logging speed. 23.The apparatus of claim 15 wherein said alteration comprises a decreasein said logging speed.
 24. The apparatus of claim 22 wherein: (i) saidprocessor in (c) analyzes measurements made by each of said plurality ofFE sensors for validity, and (ii) said processor in (d) determines ifmeasurements made by each of said FE sensors would be of acceptablequality at an increased logging speed.
 25. The apparatus of claim 23wherein: (i) said processor in (c) analyzes measurements made by atleast one of said plurality of FE sensors for validity, and (ii) saidprocessor in (d) determines if measurements made by said at least one ofsaid plurality of FE sensors is of unacceptable quality at said loggingspeed.
 26. The apparatus of claim 15 wherein said processor in (c) andsaid processor in (d) comprise a downhole processor.
 27. The apparatusof claim 15 wherein said processor in (c) and said processor in (d)comprise a surface processor.
 28. The apparatus of claim 15 wherein saidalteration further comprises controlling a spooling for controlling thespeed of said conveyance device.